whitson⁺ - Nodal Analysis Certification

1. Introduction

Complete the steps outlined below to become a certified whitson⁺ user. It includes performing a nodal analysis workflow for two wells with actual production data from the SPE Data Repository . Those certified have the software skills necessary to complete most nodal analysis and completion evaluation projects in tight unconventionals.

We'll go over two kinds of analyses, typically performed via single point in time estimates from nodal analysis:

1. Running completion design sensitivity tests to prevent a Marcellus dry gas well from liquid loading.
2. Optimizing lift gas injection rate and gas lift design to maximize produced oil rate.

Need help?

Send an e-mail to support@whitson.com.

1.1. Before Starting

Make sure you have watched these three videos in the Getting Started part of the manual (click here).

• Login (1 min)
• Overview of important basics (3 min 30 sec)
• Zoom Plots (3 min)

1.2. Create a Project

1. Go to the Projects module in the navigation panel.
2. Click ADD PROJECT at the top right.
3. Name the project "Your Name - whitson Certificate - Nodal Analysis".
4. Click SAVE.
5. All steps are shown in the GIF above.

1.3. Upload Well Data

1. Click MASS UPLOAD at the top right.
2. In the pop-up window, select EXAMPLES
3. Search for Nodal Certificate Wells and click UPLOAD
4. You can also download the data from →→ here ←← and upload the file to your project by dropping it into the MASS UPLOAD frontend.
5. All the data will be uploaded into the project. You can then close the Mass Upload pop-up window.
6. All steps are shown in the GIF.

2. Well 1: Nodal Analysis - Completion Design Sensitivity

SPE-DATA-REPOSITORY-DATASET-1-WELL-37-PHEASANT

We will start with a dry gas well, with little water production. In reality, this is the closest we will get to a "single-phase" flow problem. It is a great place to start the learning curve for unconventional well performance.

2.1. PVT

2.1.1. Reservoir Fluid Composition

1. Go to the PVT module in the navigation panel.
2. Open the Reservoir Fluid Composition Input Card
3. Click SAVE.
4. Check the predicted fluid composition by clicking the "eye icon".
5. All steps are shown in the GIF above.

2.1.2. PVT Table

1. Go to the PVT TABLE tab.
2. Click EXPORT at the top right.
3. Click EXCEL in the dropdown menu to download the table to Excel.
4. We will not use this table; this is just to show you how this is done.
5. This table represents the PVT that will be used for this well.
   It's done automatically, so just sit back and relax (:
6. All steps are shown in the GIF above.

2.2. Production Data

1. Go to the Production Data module in the navigation panel.
2. Click EDIT at the top right.
3. Change the first measured gauge pressure to 4200 psia.
4. Click SAVE.
5. Does this well have tubing installed?

This section is meant to show you how you can manually edit the production data in case that is needed. In reality, one would not need to edit or delete the production data in most cases.

You can always smooth the data using the SMOOTH button at the top right to make temporary adjustments to the rate profile.

2.3. Bottomhole Pressure Calculations

2.3.1. View Wellbore Configuration Data

The data for these wells has already been uploaded, so this is just for information.
Potential changes would be made in this view (if any).

1. Go to the Bottomhole Pressure module in the navigation panel.
2. Open the Well Data input card.
3. The (1) Well Deviation survey can be plotted by clicking the icon next to the "Deviation Survey" text.
4. Click the (2) Well Data tab. Note that the well is currently missing tubing, so the well is flowing up the casing and accordingly the flowpath is casing.
5. Click SAVE.
6. All steps are shown in the GIF above.

2.3.2. Calculate Bottomhole Pressures

1. Click the CALCULATE BOTTOMHOLE PRESSURES button.
   1. This will run the calculation for four different BHP correlations at the same time.
2. Select Woldesemayat and Ghajar as the "Bottomhole pressure to be used in calculations".
   1. The dropdown menu can be found right next to the CALCULATE BOTTOMHOLE PRESSURES button.
   2. The selected BHP is used everywhere in the software where BHPs are required (PNR DCA, FMB, RTA, Numerical Model, Nodal Analysis).
3. All steps are shown in the GIF above.

2.3.3. Liquid Loading

1. Click the Liquid Loading tab of the Bottomhole Pressure feature.
   Here, you can compare your actual gas rates to the required critical gas rates to deliver gas through the current wellbore configuration without any liquid loading issues.
2. The critical rate is computed at the end of tubing using the Turner correlation by default.
   You can always change the correlation and the depth at which these critical rates are reported.
3. Does it look like the well is going to be liquid loaded?
   You always want to ensure that the actual gas rates from the well are higher than this critical rate; this is a commonly used diagnostic for gas wells.

2.4. Flowing Material Balance

Before running nodal analysis, we'll estimate the average reservoir pressure over time with a flowing material balance (FMB). Nodal analysis will then use this pressure for the IPR, instead of assuming the initial reservoir pressure.

1. Go to the Flowing Material Balance module in the navigation panel.
2. Keep the FMB Type as Multiphase.
3. Click AUTOFIT to fit the FMB line to the data.
4. Click RUN to calculate the average reservoir pressure (p_avg) over time. Repeat AUTOFIT and RUN once more so the fit uses the updated p_avg.
5. All steps are shown in the GIF above.

You should get a contacted OGIP of about 23,283 MMscf (contacted pore volume of about 24,274 MRB). The Pressure plot on the right now shows p_avg declining from the initial 4450 psia over the well history.

2.5. Nodal Analysis

2.5.1. Create an IPR and VLP

1. Click Nodal Analysis from the navigation panel on the left.
2. Choose a date to create an IPR, VLP curve - for this case, we'll choose the most recent date which is also the default selection for generating an IPR.

Note

This automatically pulls the bottomhole pressure, reservoir pressure, gas/liquid rate and the wellbore configuration in use for the chosen date and creates a VLP case for that date. Note that this case should use the same correlation as chosen above (Woldesemayat and Ghajar) for BHP.

IPR type has two choices:

1. C & n IPR or the backpressure equation - default for Gas wells
2. Vogel IPR - default for oil wells.

For the reservoir pressure, you have the following options for the source of the average reservoir pressure for the chosen date:

1. Multiphase Flowing Material Balance (MFMB) or dry gas FMB,
2. Numerical model history match
3. Initial Reservoir Pressure - If none of these analyses have been performed, the initial reservoir pressure is assumed to be the average pressure by default.
   

In this case, we've already run the FMB in Section 2.4, so the average reservoir pressure for the chosen date is taken from the FMB - 1672.65 psia.

This also automatically runs the case and generates the VLP with solid and/or dotted lines. The dotted section of the VLP indicates the operating conditions with the well configuration in use that are likely to cause liquid loading in the well based on the critical rates.

The operating point (given by the intersection of the IPR and VLP from the wellbore configuration on the chosen date) is represented with a black marker, this represents the current gas rate and bottomhole pressure deliverable by the well configuration in use, as of the chosen date. The rate at the point of intersection is reported in the case table.

This shows that we're nearly at the point where the well will quickly start liquid loading if we continue producing it via the casing. Can we prevent this by simply lowering the casing pressure of this well or is it about time we consider installing tubing? Let's find out!

2.5.2. Adding a New VLP Case

Case 2: Add a new case - Lower Casing Head Pressure

1. For our first test, let's see the effects of lowering the casing pressure. No changes to the well configuration are needed here. We'll just rerun the VLP for a lower casing pressure and gather the intersection with the IPR to see the resulting rates.
2. You can add a new case by clicking the Modify Cases button. Replicate the first row into the second row with a quick copy-paste as shown above.
3. Name the case "CasingFlow - 200 psia CHP" and modify the Casing Pressure to 200 psia. Click SAVE.
4. The new case is run automatically, you should have two VLP curves for the two cases in the VLP cases table.

Note

Note how the intersection between the IPR and VLP shifts, representing a higher well deliverability in terms of gas rates with bottomhole pressure lowered further. This also delays liquid loading significantly because the new VLP becomes liquid loaded at much lower gas rates, down to about 3.3 MMscf/D.

2.5.3. Test Alternate Operating Strategies

Question

Instead of lowering the casing head pressure, what if we installed tubing in the well?

To run such a comparison, we need to repeat the steps above - each time, we add a new well configuration, enter the relevant wellhead pressure and other input and create a VLP case.

Let's build 2 additional VLP cases to compare installing tubing vs lowering casing head pressure:

Case 3: Add a New Well Configuration - Add Tubing to the Configuration

1. Click Modify Cases and ADD/EDIT WELLBORE CONFIGURATION to add a new configuration.
2. Any modification compared to the "Current" wellbore configuration (which is the active configuration for the selected date from the Bottomhole Pressure section) will need to be saved with a unique name. Let's call this configuration "2 7/8 TbgInstall".
3. You can use the tubing tables to add 2 7/8", 6.4 ppf tubing OD and ID up to 6500 ft (Tubing depth in MD) and choose the "Tubing" flowpath.
4. Click SAVE.
5. In the VLP cases table, add a new VLP case - call it "2-7/8in TBG - 967 psia THP".
6. Use a tubinghead pressure of 967.95 psia and a casinghead pressure of 200 psi.
7. Make sure to activate the new well configuration (2 7/8 TbgInstall) for this case in the Configuration column.
8. Click SAVE. See steps in the GIF above.

Note

The Configuration column dictates which configuration will be used to calculate the VLP. We need to choose this saved configuration for the appropriate VLP case to ensure that it uses the saved configuration to calculate BHP instead of the current configuration.

Case 4: Add a New Well Configuration - Let's Try a Different Tubing Size

1. Click Modify Cases and ADD/EDIT WELLBORE CONFIGURATION to add a new configuration.
2. Let's call this configuration "2 3/8 TbgInstall".
3. You can use the tubing tables to add 2 3/8", 4.6 ppf tubing OD and ID up to 6500 ft (Tubing depth in MD) and choose the flowpath as Tubing. Click SAVE.
4. Add another VLP case - call it "2-3/8in TBG - 967 psia THP".
5. Use a tubing head pressure of 967.95 psia.
6. Choose the newly created configuration "2 3/8 TbgInstall" using the dropdown in the Configurations column.
7. Click SAVE. All these VLP cases should calculate automatically and plot on the IPR-VLP plot. The VLP cases table summarizes the cases with the gas rate at intersection.

Notice how the smaller tubing has a higher frictional pressure drop, so it results in a slightly lower rate but increased BHP and a much more delayed liquid loading.

Note

Since we added tubing to the configuration and the flow is up the tubing, the casing pressure used is no longer relevant to the VLP and only the tubing pressure will make a difference. For the purpose of continuity, the tubing pressure used above is the casing pressure that the well was being produced with, on that chosen date.

All the steps are shown in the GIFs above.

2.5.4. Saving VLP Cases, Viewing/Editing Wellbore Configurations in Use

1. All the cases added to the VLP cases table are automatically saved. You can work on other things and when you navigate to nodal analysis for this well, it will be exactly as you left it previously.
2. To compare all or a few of these cases, you can toggle the cases on/off by clicking the legend entries.
3. To adjust or view the wellbore configuration in use, click Modify Cases and ADD/EDIT WELLBORE CONFIGURATION. Select the configuration you want to edit from the dropdown, then click SAVE to update it.

All these steps are shown in the GIF above.

2.5.5. Forecasting with Different Tubing Sizes

The nodal forecasting module allows us to predict how long we will be able to run for before an intervention is required (e.g. the well becomes liquid loaded, or the well stops producing).

To test this, navigate to the FORECAST tab.

The forecast starts from the IPR on the chosen date and uses the FMB (Material Balance / Tank Data card) to step the average reservoir pressure forward in time, solving the IPR/VLP intersection as it goes. On the main plot, the black dashed line is the current IPR date and the blue dashed line is the forecast date shown on the FUTURE IPR | VLP plot on the left - drag it to move through time. Aqua shading marks periods where the gas rate is below the critical rate. The Forecast Cases table reports the BHP, gas rate and critical rate on the selected forecast date, plus the cumulative production.

Seeing a little orange warning icon?

If an orange warning icon appears next to the Productivity Index Data or Material Balance / Tank Data cards, the forecast is using outdated inputs. This happens when something has changed since the forecast was last set up, such as a new FMB fit or a different IPR date.

Click the refresh button (↻) next to that card to pull in the latest FMB / IPR results. The warning should disappear, and the forecast will now use the up-to-date average reservoir pressure and IPR curve.

If we keep flowing up the casing as we are today, the forecast drops below the critical rate around day 784 - only about two weeks after the current IPR date (day 771).

Navigate into "MODIFY CASES". We are going to test how long we can run on 2 7/8" tubing, and compare this to how long we could run on 2 3/8" tubing. Let's assume that the WGR for this well will be constant across the entire 3000 days, while the WHP declines at a rate of 20% per annum. In the Main case:

1. Under WHP / Configurations, set SEGMENTS to 2. Keep the first segment "Current" (ending on day 780, Configuration "Current"). Name the second segment "2 7/8" Tubing", set the Segment End Time to 3000 days, Pressure Decline to 20 and Configuration to "2 7/8 TbgInstall". The WHP declines from 967.95 psia to 434.57 psia by day 3000.
2. Under WGR, set the Segment End Time to 3000 days and WGR = 0.2 STB/MMscf.
3. Under OGR, set the Segment End Time to 3000 days and OGR = 0.
4. Click SAVE.

Then add a new case called "2 3/8" by clicking the + button (this copies the Main case). Rename the second segment "2 3/8" Tubing" and set its Configuration to "2 3/8 TbgInstall". Click SAVE.

Now drag the blue line on the main plot to the point at which an intervention is required. Observe on the Future IPR/VLP plot that the VLP curve is feathering the very top of the IPR curve. Much further into the future, there is no solution between the IPR and VLP curves.

You may notice that the 2 7/8" gas rate reappears on the plot after a gap, at around day 2230, even though the well has effectively stopped producing. When there is no intersection between the IPR and VLP, the forecast treats the well as not flowing. No gas is withdrawn, so the average reservoir pressure from the material balance stays flat. However, the tubinghead pressure in the forecast schedule keeps declining at 20% per year, which pulls the VLP curve down. Eventually the VLP drops back below the IPR and a solution reappears, so the forecast resumes. This later rate sits on the liquid-loaded (dotted) side of the VLP and below the critical rate. In practice, the well would not restart on its own: it would need an intervention, such as unloading, swabbing or a compressor to lower the wellhead pressure. That is why we take the first loss of a solution, around day 2000, as the end of the well’s natural flowing life on 2 7/8" tubing.

2.5.6. Conclude

We used nodal analysis to see if this gas well can be prevented from liquid loading in the near future by adjusting the operating conditions:

1. You can modify the current case by changing the date input on the left, as the changes in the current case can not be made in the ADD/EDIT WELLBORE CONFIGURATION.
2. Click on the date and a screen will appear. You can adjust the date by moving the vertical dashed line to the desired date or manually type the days.
3. Click Save. You can see the changes in the current case.

Bonus questions

1. Which operating conditions offer the highest incremental rate? Does this prevent liquid loading?
2. Which configuration would you pick to sustainably prevent liquid loading for the longest time and why?

You can include these answers along with your certificate project submission below.

3. Well 2: Nodal Analysis - Gas Lift Optimizer

This workflow will be done on a different well in the same project called "SPE-DATA-REPOSITORY-DATASET-1-WELL-2-HAWK".

This is an Eagleford black oil well. The preliminary steps to conduct this analysis include initializing PVT, updating the wellbore configurations to include gas lift valve details, and calculating BHP while viewing gas injection depths over time.

The rest of the workflow involves using Nodal analysis, and specifically the gas lift optimizer, where we will examine the effects of altering gas lift injection rate on produced oil and find the optimal gas injection rate to maximize production. We will also conduct a lookback by picking a date when the gas lift injection was much lower than this optimum to see the potential upside of increasing the lift rate sooner.

1. Click Wells from the navigation panel on the left.
2. Click the SPE-DATA-REPOSITORY-DATASET-1-WELL-2-HAWK

3.1. PVT

1. Navigate to the PVT section and click the edit icon on the Reservoir Fluid Composition card. Note that the initial GOR was preloaded from the mass upload for this well.
2. Click Save. This generates the fluid composition and the relevant black oil tables.

3.2. Bottomhole Pressure Calculations

3.2.1. Correcting Wellbore Configurations - Adding Valve Details

1. Go to the Bottomhole Pressure module in the navigation panel.
2. Open the Well Data input card.
3. Click the (2) Well Data tab. Note that there is only one configuration here since the gas lift calculation is only activated for the days when there are gas lift injection rates in the data. For the days that do not have gas lift rates, the BHP calculation simply assumes tubing flow with no artificial lift.
   Choose 'Valves' for 'Gas Lift Configuration' and click the edit icon to enter the valve details (depths, opening and closing pressures) as follows:

Valve MD (ft)	PSO (psia)	PSC (psia)
1500	1158	982
3000	1120	950
5000	1060	870
7000	1015	834

1. Click Save to save the valve details, then click Save again to save the wellbore configuration. All these steps are shown in the GIF above.

3.2.2. Calculate BHP and View Gas Injection Depths

1. Click the CALCULATE BOTTOMHOLE PRESSURES button.
   1. This will run the calculation for four different BHP correlations at the same time. For gas lift wells, this also calculates the operating valve (i.e. the valve that the lift gas is injected into - depending on the casing and tubing pressures) for the gas lifted portion of the well history.
2. Select Woldesemayat and Ghajar as the "Bottomhole pressure to be used in calculations".
   1. The dropdown menu can be found to the right of the CALCULATE BOTTOMHOLE PRESSURES button.
   2. The selected BHP is used everywhere in the software where BHPs are required (PNR DCA, FMB, RTA, Numerical Model, Nodal Analysis).
3. Click the Gas Lift Plot to view the gas injection depths vs time for the given gas lift design - just double-click the 'Gas-Lift Valve Depth' in the plot legend to isolate this data on the plot. You can also enable gas lift valve depths to see where the installed valves are located in the wellbore.

Notice how the gas lift injects shallow at the beginning and eventually reaches the deepest valve at later times with increased rates, so there might be potential for further optimization.

3.3. Flowing Material Balance

As for the gas well, we'll run a flowing material balance so that nodal analysis uses the current average reservoir pressure.

1. Go to the Flowing Material Balance module in the navigation panel.
2. Keep the FMB Type as Multiphase.
3. Click RUN to calculate p_avg. Adjust the slope to achieve the shallowest slope that you can interpret, then RUN to calculate p_avg.
4. All steps are shown in the GIF above.

You should get a contacted pore volume of about 5,621 MRB. The average reservoir pressure on the most recent date (used in the IPR below) is 2889.68 psia, well below the initial 5650 psia. We want to ensure that the vast majority of wellface pressures are below the calculated reservoir pressure displayed on the pressure plot.

3.4. Optimizing Gas Lift Rates

Why optimize gas lift?

Gas lift is a useful form of artificial lift that works by primarily lowering the density of fluid column in the wellbore, effectively reducing the hydrostatic pressure. This indirectly increases the pressure differential (drawdown) between the reservoir and the bottomhole, hence enhancing more fluids to flow or be produced.

Optimization of a gas lifted well may involve changing gas injection rate, pressure, etc. to control the gas injection depth in the wellbore and hence reduction in the bottomhole pressure. The most optimized design injects as deep as possible into the wellbore and yields the maximum reduction in bottomhole pressure.

A diminishing return can be anticipated when the design parameters are pushed to inject more gas into the wellbore. The gas injected in excess of this optimal limit has a higher frictional pressure drop in the wellbore, which in turn, yields a higher bottomhole pressure and reduces the production rate.

3.4.1. Step 1: Nodal Analysis

1. Navigate to Nodal Analysis.
2. Ensure that the most recent date is selected for the IPR - that should be the default. This pulls in the current gas lift configuration in place and the associated BHP, rates available for generating the IPR.
3. This automatically generates a VLP curve for the current conditions and the intersection represents the current operating point with the associated gas lift rates and wellhead pressures on that day.

We could manually add multiple VLP cases with different lift gas rates here to find the most optimal gas-lift injection rate that lowers BHP and maximizes liquid production rates.

Instead, we'll skip this sensitivity analysis and directly use the Gas lift Optimizer (which does that for you) below.

3.4.2. Step 2: Gradient Calculator

1. Switch over to the Gradient Calculator tab on the top. The conditions on the selected date in IPR-VLP are automatically the first, default case.
2. Gradient cases are listed at the top, you can build alternate cases by clicking Modify Cases as shown in subsequent steps.
3. Click RUN to generate the pressure traverse curves i.e. pressure drop through the wellbore down to the MD/TVD. The case we just ran plots the pressure drop in the wellbore for the chosen date in IPR, along with gas rates and velocities - actual and critical to see the length of the wellbore under likely risk of liquid loading.
4. Click the summary button to see the complete set of calculated values vs depth, expected flow regimes in the pipe, etc.
5. You can switch between pressure vs TVD and pressure vs MD.
   

Why does pressure vs MD look counter-intuitive?

To answer this question, we need to take a look at the deviation survey to see the toe and the heel of the lateral:

The well construction is toe-up, such that the toe of the lateral is shallower than the heel of the well lateral. This creates a lower pressure at the toe and higher pressure at the heel which causes this shape in pressure vs MD.

3.4.3. Step 3: Gas Lift Opt

1. Switch over to the Gas Lift Opt tab on the top.
2. This plot shows you the oil rate yield curve, where the incremental oil recovery with incremental increase in gas injection rate can be plotted based on the IPR/VLP for that chosen date.
3. The plot shows the current operating point with an X marker and the most optimal operating conditions with the circle marker. The curve itself shows that the oil recovery reduces with an increase in gas lift rate beyond the optimal point.
4. You can add additional cases by clicking MODIFY CASES to adjust parameters such as tubing and casing pressure. This also allows for the option to modify the wellbore configuration to generate the gas lift optimization curve for alternate strategies (such as injecting via the tubing or modified gas lift valve depths).

Notice that this analysis recommends increasing the gas injection rate by ~896 Mscf/D to about 1112 Mscf/D to produce an additional 136 STB/D. This additional recovery can be achieved, at times with minor modifications to gas lift wells.

On the flip side, we can also see the impact turning off gas lift - the point where the curve intersects the y-axis (lift gas injection rate = 0) represents the achievable oil rates with the same wellbore configuration if the gas injection was completely turned off. From the plot here, we can see that the well would make essentially no oil (~0 STB/D) with no lift-gas injection - at the current reservoir pressure, it can no longer flow naturally! The dashed/solid in the curve also shows the minimum gas lift rate to lift without these liquid loading issues - you can infer this critical rate from the table at the top which summarizes key results.

3.4.4. Step 4: Economic Optimization

Economic Optimization evaluates gas lift performance on production response and economic assumptions. The optimizer estimates the most economic gas lift rate by comparing the value of the produced hydrocarbons against the cost of the injected lift gas.

1. In the Gas Lift Opt tab in the box on the left, click the empty square next to Economic Optimization.
2. This allows setting of Oil Price, Gas Price, and Lift Gas Cost. It also adds to the Gas Lift Cases table the Economic Oil Rate (STB/d), the Economic GL (Mscf/d), and then shows where these two points sit on the graph indicated by the diamond.
3. whitson⁺ automatically puts the values at 50 (USD/STB) for Oil Price, 4 (USD/Mscf) for Gas Price, and 0.4 (USD/Mscf) for Lift Gas Cost, you can then change these to match whatever your current prices are or what you are forecasting.
4. Input 80 for you Oil Price value and 1.5 for your Lift Gas Cost, then press enter. Both the table and graph will automatically update to match the changes you have made.

Notice that this analysis for optimization economically recommends a GL of 980.7 (Mscf/d) and an Oil Rate of 573 (STB/d).

Keep in mind this is not for optimum production which is why its producing values less than the previous step, but instead these calculated values are for what is most economically optimum based on the equation discussed in the manual. Another key concept of this optimizer to keep mind of is due to how the calculations are done, small incremental changes of just one value of the three will likely show no changes to the table or graph due to how slight of a mathematical difference it makes. This is especially apparent on when changing Gas Price on an oil well, and Oil Price on a gas well.

3.5. Evaluate Future Gas Lift Requirements

Let's use the forecast to see what happens if we keep the current gas lift rate, and what we gain by increasing it.

1. Navigate to the FORECAST tab. The Main case continues the current conditions: 216 Mscf/D of lift gas, with the tubinghead pressure (152.3 psia) declining at 20%.
2. Open MODIFY CASES and set the Segment End Time of the WHP / Configurations, GOR and WOR segments to 3000 days, keeping GOR at 176.69 scf/STB and WOR at 0.28 STB/STB. Click SAVE.
3. Drag the blue forecast-date line to the end of the forecast.

With the current lift rate, the oil rate drops from 438 STB/D to about 116 STB/D by day 3000, and the aqua shading shows that the well is below the critical rate for the entire forecast - it is liquid loaded. The cumulative oil at the end of the forecast is about 515 MSTB.

Now let's increase the gas lift rate to 1000 Mscf/D - close to the optimum found in Section 3.4.3. Open MODIFY CASES:

1. Under WHP / Configurations, set SEGMENTS to 2. Keep the first segment "Current" (THP 152.30 psia, Pressure Decline 20, Gas Lift Rate 216 Mscf/D) and set it to end on day 450.
2. Name the second segment "GL=1000", set the Segment End Time to 3000 days, Pressure Decline to 0, Configuration "Current" and Gas Lift Rate to 1000 Mscf/D.
3. Under GOR, set the Segment End Time to 3000 days, keeping GOR constant at 176.69 scf/STB.
4. Under WOR, set the Segment End Time to 3000 days, keeping WOR constant at 0.28 STB/STB.
5. Click SAVE.

Once the lift gas rate is increased on day 450, the oil rate jumps and the well is no longer below the critical rate. On day 3000 the well makes 128.6 STB/D (vs 116.1 STB/D), and the cumulative oil increases to about 587 MSTB - an extra ~72 MSTB compared to keeping the current gas lift rate.

3.6. Lookback - When the Gas Lift Rate was Lower

3.6.1. Lookback - IPR/VLP

1. Navigate back to IPR/VLP tab and add a new scenario, let's call it "Lookback"
2. Pick 25th February 2021 (or day 56 in the well history) to calculate the IPR and VLP for that date - The reason we choose this date for a lookback is because we were injecting much lower gas-lift rates, so there should be a much higher margin for optimization.
3. This action will automatically populate the "Current" case with conditions from day 56.
4. Now, navigate back to "Main" scenario and open MODIFY CASES. Copy all the input values from the "Current" case in the table.
5. After copying these values, return to the "Lookback" scenario, open MODIFY CASES, and create a new case below the "Current" case called "Lookforward". Paste the previously copied values from the "Main" scenario.

Notice how the Reservoir Pressure in the Productivity Index Data card has increased to 3922.5 psia, compared to 2889.68 psia on the most recent date. This value comes from the FMB we ran in Section 3.3 - the average reservoir pressure is taken from the FMB for whichever date is chosen, so going back in time gives a higher, less depleted reservoir pressure.

On this date, the well was only injecting 42 Mscf/d of lift gas, and the intersection with the IPR gives a bottomhole pressure of 2890.21 psia and an oil rate of 923 STB/d (1303 STB/d liquid).

Based on "Lookback" IPR, the intersection of a GL rate = 42 Mscf/d (Current) results in higher bottomhole pressure and lower oil rate, indicating not an optimal gas-lift injection compared to a GL rate = 216 Mscf/d (Lookforward).

Creating a scenario in whitson⁺

When you click on "Add a new scenario" from anywhere in the software (Dropdown right up top or the Scenarios page), you take the current scenario you are on (i.e. all the analyses/interpretation/input you have in there) and create a copy. All scenarios refer to the production data in the 'Main' scenario - so you will not be allowed to edit the production data from any of the scenarios (other than 'Main') - but you can edit all other input (including smoothing on the production data) without affecting any other scenario.

Another pro-tip: If you want to create a copy of a particular scenario, first navigate to that scenario (by clicking on it from the dropdown) and then click the "Add scenario" button. Creating a scenario always copies everything from the scenario it is created from.

3.6.2. Lookback - Gradient Calculator

Let's run the gradient calculator for this case to confirm that this gas lift injection rate yields a much higher bottomhole pressure:

1. Navigate to the Gradient Calculator tab on top.
2. Under the list of Gradient Cases, click the Modify Cases button on the right.
3. Here, instead of replacing the case we originally set up for the most recent date, we'll add a case. Let's call it "Lookback" and use the date picker in the table to select day 56 and pull all the associated values required for the table. Click SAVE.
4. Automatically, your new case should be running and you should be able to see the results on the plots below these cases.

You see that the bottomhole pressure for the lookback case shows much higher bottomhole pressure at TVD compared to the most recent case. Is the pressure gradient (psi/ft) in the wellbore higher or lower for the new case we just added above?

Tip

If an orange exclamation mark appears next to the case, that means the input has changed, making the results outdated. Click RUN to recalculate.

3.6.3. Lookback - Gas Lift Optimizer

Next, we'll run the gas lift optimizer for this date, steps shown in the GIF above:

1. Navigate to the Gas Lift Opt tab on top.
2. Click "Fetch Values from the IPR". This ensures that the gas lift optimizer is using the appropriate data as in the IPR/VLP section.
3. Notice how the gas lift optimization curve is automatically recalculated?
4. The warning sign, if any, should be replaced with a green check mark when done. Time to look at the results!

It shows that the margin for improvement is much higher. If we increased the lift gas injection rate to 1621 Mscf/D, we have the potential to recover about 1429 STB/D instead of the 923 STB/D in oil rates - this is an increase of almost 506 STB/D!

The gas lift optimization curve also shows that the lift gas injection rate used on this date is barely effective - turning it down all the way to 0 Mscf/D still allows the well to deliver about 860 STB/D, although both points sit on the dashed part of the curve, below the minimum rate to lift without liquid loading issues.

3.7. Conclude

This clearly outlines the benefits of using Nodal Analysis - specifically the gradient calculator and the gas lift optimizer, in this case to improve the lift efficiencies and test alternate strategies of lift gas injection rate and pressure combinations to optimize the well deliverability.

Such analyses are invaluable to all producing wells, so we can operate them at much higher efficiency.

Bonus questions

1. If we did not have the additional gas available to inject, how would you use nodal analysis to prove that you can produce the same rate uplift without changing the current gas injection rate? What would you prefer to change in this configuration?

2. Can you prove your plan with a quick gas lift optimization calculation?

4. Done?

When you are done with your analyses, please:

1. Send an e-mail to certification@whitson.com
2. Make the subject: "whitson⁺ Nodal Analysis certificate: [YOUR NAME HERE]"
3. Include the link to your project.
4. If you have any notes, comments, or observations related to the exercise, feel free to share them with us. Also feedback on the user friendliness of the software is always appreciated.

After that, we'll provide some feedback on your evaluation and issue your whitson⁺ certificate if all looks good.

Cheers and Congratulations!